The present invention relates to oil well logging, and more particularly to methods and apparatus for measuring and monitoring horizontal formation fluid flow using radioactivity well logging techniques.
In the secondary and tertiary enhanced recovery of oil, many techniques employ the injection of water or chemical solutions into the reservoir formations. To flood the reservoir effectively, horizontal continuity must exist between injection and production wells, and good vertical conformance of the injected fluids must be maintained.
Intervals which have been inferred to be correlative from log data may in fact be separated from one well to the next by reduced permeability. This can be caused, for example, by natural factors such as formation lensing, or horizontal partitioning by permeability barriers such as shale or faults. Reduced permeability can also be caused by factors resulting from production operations, such as migrating fines, swelling clays, emulsion blocking, scale and paraffin deposition, and sand production.
Conversely, situations can arise where a zone may carry away excessive injection fluids. Such thief zones can be caused by channeling into adjacent beds or by fractures in the reservoir, and the resulting losses can be very costly.
When planning the injection of water or costly chemicals into a recovery pattern, it is thus important to identify and determine the magnitude of any such problems well in advance. Radioactive injection surveys, well-to-well pressure testing, and chemical tracer surveys can provide useful data. These techniques are somewhat qualitative in layered reservoirs and, in the case of tracer surveys, can require several weeks to obtain definitive results.
In such secondary and tertiary oil field operations it is thus often desirable--even necessary--to measure specifically the horizontal flow of injection fluids in selected zones of a downhole formation reservoir. Not only is this information useful in determining whether correlative zones in different wells (e.g., an injector and a producer) are in communication, but the nature of the communication and the relative flow rates can be determined as well.
Measuring horizontal water flow in the past has primarily utilized the injection of a tracer in one well and its subsequent detection in a nearby producer well. As suggested above, this is very time consuming since it requires the tracer to move physically between the wells. It is also expensive since continual monitoring or sample testing is required. Further, if the tracer should move (e.g., through a fault or channel) into some other zone, it might never be detected.
One previously known and described technique eliminates some of these problems in unperforated monitor wells in areas having saline waters. (See U.S. Pat. No. 4,051,368, Arnold et al., issued Sept. 27, 1977; and "Logging Method for Determining Horizontal Velocity of Water in Oilfield Formations" by H. D. Scott and H. J. Paap, and D. M. Arnold, Journal of Petroleum Technology, April, 1980, pp. 675-684). In this technology, a neutron source is used to generate in-situ a 15 hour half-life Na.sup.24 tracer in the formation of interest. A spectral gamma detector is then moved opposite the activated zone and the rate of Na.sup.24 decay is measured. If an apparent non-exponential decay rate faster than the theoretical 15 hour half-life is observed, then the faster-than-expected decay is attributed to movement of the tracer away from the wellbore due to water movement. The rate of water flow can be determined from the actual shape of the decay curve--the faster the flow the more rapid and non-exponential is the Na.sup.24 apparent decay. This technique has several advantages over prior techniques: it is much faster, and it actually samples the fluid flow in the well of interest. Unfortunately, it also has several limitations which in some environments are not significant, but in others can be troublesome. Some of these are:
(1) Only a limited number of depth points can be measured in a well in a reasonable time. That is, the source must be accurately placed for 2 hours activation, and the detector then accurately placed to monitor the decay for several more hours. All of these steps must be performed for each individual water flow data point. PA1 (2) The observation well cannot be perforated. PA1 (3) The technique is restricted to saline waters-the fresher the water (and hence the less sodium in the fluid), the lower the reliability of the technique. PA1 (4) Flow rates only in a limited velocity range can be detected. Very fast flow rates are not suitable for monitoring within a 15 hours half-life isotope; very slow flow rates are not suitable either. PA1 (5) There are many interfering half-lives from other downhole elements activated by the source, and these cause difficulty in interpreting the data. The most important is the 2.5 hour half-life from activated iron in the casing. These interfering elements can also restrict the flow rates which it is possible to measure.
A need therefore remains for formation fluid flow measuring methods and apparatus which can make such measurements in reasonable periods of time, in perforated wells, independently of the properties of the particular formation fluid of interest, over a wide range of formation fluid flow rates, without interference from extraneous radioactivity emissions; and which are inexpensive, uncomplicated, highly versatile, reliable, and readily suited to the widest possible utilization in formation fluid flow measuring and monitoring.